A seismic survey represents an attempt to image or map the subsurface of the earth by sending sound energy down into the ground and recording the “echoes” that return from the rock layers below. The source of the down-going sound energy might come, for example, from explosions or seismic vibrators on land, or air guns in marine environments. During a seismic survey, the energy source is placed at various locations near the surface of the earth above a geologic structure of interest. Each time the source is activated, it generates a seismic signal that travels downward through the earth, is reflected, and, upon its return, is recorded at a great many locations on the surface. Multiple source/recording combinations are then combined to create a near continuous profile of the subsurface that can extend for many miles. In a two-dimensional (2D) seismic survey, the recording locations are generally laid out along a single line, whereas in a three dimensional (3D) survey the recording locations are distributed across the surface, traditionally as a series of closely spaced adjacent two-dimensional (2D) lines. In simplest terms, a 2D seismic line can be thought of as giving a cross sectional picture (vertical slice) of the earth layers as they exist directly beneath the recording locations. A 3D survey produces a data “cube” or volume that is, at least conceptually, a 3D picture of the subsurface that lies beneath the survey area. In reality, though, both 2D and 3D surveys interrogate some volume of earth lying beneath the area covered by the survey.
A seismic survey is composed of a very large number of individual seismic recordings or traces. In a typical 2D survey, there will usually be several tens of thousands of traces, whereas in a 3D survey the number of individual traces may run into the multiple millions of traces. (Chapter 1, pages 9-89, of Seismic Data Processing by Ozdogan Yilmaz, Society of Exploration Geophysicists, 1987, contains general information relating to conventional 2D processing and that disclosure is incorporated herein by reference. General background information pertaining to 3D data acquisition and processing may be found in Chapter 6, pages 384-427, of Yilmaz, the disclosure of which is also incorporated herein by reference.
A seismic trace is a digital recording of the acoustic energy reflecting from inhomogeneities or discontinuities in the subsurface, a partial reflection occurring each time there is a change in the elastic properties of the subsurface materials. The digital samples are usually acquired at 0.002 second (2 millisecond or “ms”) intervals, although 4 millisecond and 1 millisecond sampling intervals are also common. Each discrete sample in a conventional digital seismic trace is associated with a travel time, and in the case of reflected energy, a two-way travel time from the source to the reflector and back to the surface again, assuming, of course, that the source and receiver are both located on the surface. Many variations of the conventional source-receiver arrangement are used in practice, e.g. VSP (vertical seismic profiles) surveys, ocean bottom surveys, etc. Further, the surface location of every trace in a seismic survey is carefully tracked and is generally made a part of the trace itself (as part of the trace header information). This allows the seismic information contained within the traces to be later correlated with specific surface and subsurface locations, thereby providing a means for posting and contouring seismic data—and attributes extracted therefrom—on a map (i.e., “mapping”).
The data in a 3D survey are amenable to viewing in a number of different ways. First, horizontal “constant time slices” may be taken extracted from a stacked or unstacked seismic volume by collecting all of the digital samples that occur at the same travel time. This operation results in a horizontal 2D plane of seismic data. By animating a series of 2D planes it is possible for the interpreter to pan through the volume, giving the impression that successive layers are being stripped away so that the information that lies underneath may be observed. Similarly, a vertical plane of seismic data may be taken at an arbitrary azimuth through the volume by collecting and displaying the seismic traces that lie along a particular line. This operation, in effect, extracts an individual 2D seismic line from within the 3D data volume.
Seismic data that have been properly acquired and processed can provide a wealth of information to the explorationist, one of the individuals within an oil company whose job it is to locate potential drilling sites. For example, a seismic profile gives the explorationist a broad view of the subsurface structure of the rock layers and often reveals important features associated with the entrapment and storage of hydrocarbons such as faults, folds, anticlines, unconformities, and sub-surface salt domes and reefs, among many others. During the computer processing of seismic data, estimates of subsurface rock velocities are routinely generated and near surface inhomogeneities are detected and displayed. In some cases, seismic data can be used to directly estimate rock porosity, water saturation, and hydrocarbon content. Less obviously, seismic waveform attributes such as phase, peak amplitude, peak-to-trough ratio, and a host of others, can often be empirically correlated with known hydrocarbon occurrences and that correlation applied to seismic data collected over new exploration targets.
However, for all of the advances that have been made in recent years in the technology of seismic processing, the resulting image of the subsurface is ultimately limited by the quality of the seismic data that is collected in the field. In more particular, and has been observed in a variety of different contexts, in order to accurately image complex subsurface structures the seismic data must be illuminated from a variety of different offsets and azimuths. So-called wide azimuth surveys have been done for many years on land and such surveys have proven in many cases to yield superior data that can be subsequently migrated or otherwise imaged to produce an improved picture of the subsurface as compared with traditional/narrow azimuth surveys.
Traditionally, marine seismic data are acquired via a towed streamer survey. As is generally indicated in FIGS. 3A and 3B, in a conventional arrangement a vessel tows several hydrophone cables behind it (i.e., several “streamers” in the argot of the trade) as it steams over a subsurface area of interest. Each streamer will typically contain several hundred hydrophones which are designed to sense seismic signals that have been reflected from subsurface rock formations and other density contrasts.
At periodic intervals, a seismic source (that is typically also towed by that vessel and located directly behind it) is activated. The source energy propagates downward through the water and penetrates into the ocean bottom, where it is ultimately encounters subsurface rock formations that reflect part of the down going energy back up toward the receivers. Recordings are made of the sensor responses for a short period of time after the source is activated (e.g. for 10 to 20 seconds) at a sample interval that is often either 2 ms or 4 ms
For all of its usefulness, conventionally acquired marine seismic data have been shown to be a less than perfect means of exploring for hydrocarbon reserves when such are located beneath complex structures such as salt domes. Further, and this is especially true in the case of offshore prospects, the conventional means of collecting seismic data (e.g., via a marine survey) have heretofore been designed to acquire seismic data that sample the subsurface over only a limited range of azimuths (see, e.g., FIGS. 3A and 3B).
One important consequence of collecting data that illuminates the subsurface over a limited range of angles is that the resulting seismic volumes and sections will potentially be imperfect representations of the subsurface, and, thus, may cause false prospects to be drilled and/or promising targets to be missed.
Heretofore, as is well known in the seismic processing and seismic interpretation arts, there has been a need for a method of identifying and interpreting thin bed reflections. Accordingly, it should now be recognized, as was recognized by the present inventor, that there exists, and has existed for some time, a very real need for a method of seismic data processing that would address and solve the above-described problems.
Before proceeding to a description of the present invention, however, it should be noted and remembered that the description of the invention which follows, together with the accompanying drawings, should not be construed as limiting the invention to the examples (or preferred embodiments) shown and described. This is so because those skilled in the art to which the invention pertains will be able to devise other forms of this invention within the ambit of the appended claims.